Gas streams, such as those which result from petroleum processing or combustion processes, often contain a gas or gases which form an acid when mixed with water. Such gases are typically called “acid gases”. The most common naturally occurring acid gases resulting from petroleum processing are hydrogen sulfide (H2S) and carbon dioxide (CO2). Typical acid gases derived from combustion/oxidation/pyrolysis processes are carbon dioxide (CO2), sulphur dioxide (SO2), and nitrogen oxides (NO, NO2).
Acid gases typically contain water. Naturally occurring acid gases are often saturated with water in the reservoir and combustion-derived gases co-exist with the water formed from the reaction of hydrogen and oxygen during combustion. Virtually all acid gases eventually end up being saturated with water vapour at some point during the process of removal or purification of the acid gas. Reducing the temperature or increasing the pressure, over a defined range, of an acid gas containing water, such as that which occurs when the acid gas is passed through a compressor, will result in the condensing of some of the water from a gas to a liquid phase. At some temperature, still above the freezing point of water, the water and acid gas may begin to form a “solid like” structure called a gas hydrate. The temperature at which hydrates may begin to form is called the Hydrate Formation Temperature (HFT) which varies according to the pressure, composition and water content of the mixture. Hydrates are the physical combination of water and small molecules producing a compound having an “ice like” appearance, but possessing different properties and structure than ice. Hydrates may also be known as gas clathrate. Hydrates are problematic as they can cause reduced heat transfer, excess pressure drops, blockages, interruptions in production and are a safety concern.
The formation of an aqueous phase in any gas system is undesirable as it promotes corrosion, can cause gas hydrates to form and can cause mechanical and operational problems. An aqueous phase is particularly undesirable in an acid gas system as the resulting aqueous phase will be acidic, resulting in a significant increase in the corrosion rate and usually resulting in a higher HFT than non-acid gases.
Table A illustrates the levels of corrosion which occur in mild steel at varying concentrations of acid gas components in water.
TABLE ACorrosion of Mild Steel by CarbonDioxide and Other Gases in Water*O2 conc.H2S conc.Corrosion mils/yrCorrosion mils/yrppmppmCO2 conc, 200 ppmCO2 conc, 600 ppm8.8028604.3018441.6012340.401727<0.535660.51501516<0.54001721*Temperature 80° F., exposure 72 hr.Source: Data of Watkins and Kincheloe (1958) and Watkins and Wright (1953)Although the discussion has focused on acid gas, it will be appreciated by those skilled that the methodology and concept is applicable for removing condensable components from any fluid stream exhibiting a positive Joule-Thomson coefficient.